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Sunday, November 29, 2009

I just read an article that the Mexican government has ordered state-owned energy company Pemex to cut way back on flaring gas from its oil fields. Flaring is the act of burning off gas that is extracted along with oil when there is no use for the gas. In Mexico's case, its large Cantarell Field doesn't have gas treatment facilities, so it burns off one billion cubic feet per day (1 Bcf/day). Think of that volume of gas - it's enormous. In some places natural gas is an annoyance. In Alaska, for instance, there is no way to get much of that gas to the Lower 48 - that's why the state is working on the AGIA pipeline.

Mexico shouldn't have that same problem. It seems to me if you're flaring the equivalent "street value" of $3.1 billion per year, you can afford to build gas treatment and transportation infrastructure. The only reason it has become an issue now is because it is one of the leading causes of greenhouse gas emissions in Mexico.

Gammage #1, EOG Resources: 10.352 MMcf/day on 18/64” choke; North Carthage Field, Nacogdoches Co. (this was previously reported in October at 2.395 MMcf/day – not quite sure what is going on with this…)

Thursday, November 26, 2009

That headline alone should be enough to cause prices to crash (hopefully by adding extra question marks, I lessened the blow). This evening, I read an article in the Canadian Globe and Mail about the recent spike in the price of front month natural gas futures since Wednesday's release of the EIA gas storage data. Seems like a weak premise to me since the report showed an increase of gas in storage three weeks into November, but when it comes to gas prices, I don't know what to believe. I'm guessing it's more the result of trader speculation than fundamental changes, but I long ago gave up trying to make predictions.

Recently Devon Energy announced that it will sell its offshore and international assets to concentrate on onshore domestic natural gas plays. Now comes the shareholder approval of EnCana's plan to split into two companies, EnCana, which will focus on North American natural gas, and Cenovus Energy, which will hold the company's oil assets. EnCana becomes another company de-diversifying into North American natural gas.

This was a move to appease investors who didn't value the hybrid oil/natural gas company as highly as they would if they were two pure play companies. It also creates the opportunity for one or both of the businesses to be acquired, which would also boost shareholder value.

I just wonder about the move from a business plan perspective. This split, which has been in the works for more than a year, comes at a time when gas prices are sucking wind and don't see much light at the end of the tunnel. In fact, EnCana doesn't see gas prices above $5.50 in 2010 or above $6.50 for the foreseeable future. Companies like EnCana and Devon seem to see the benefit of re-creating their businesses around mass producing gas in a factory-like, low cost environment.

To me it is another indication how shale gas has changed the natural gas industry almost overnight. It seems to have furthered the trend for the domestic natural gas industry to move from a highly fragmented base of small independent producers to fewer, larger companies that look more like the energy "majors" than their ancestors.

This is interesting because it shows that one can apparently make money liquefying gas, loading it into an expensive boat, shipping it across the ocean, offloading it, storing it for a few months, loading it back on a boat, shipping it across the ocean and offloading it. What a kooky natural gas market. I'm sure nobody wrote their business plan to reflect this reality, but the LNG importers are going to have to do whatever they can to survive in a shale gas world.

This week I’ve been reflecting on the things for which I am thankful, as most people do this time of year. In regards to this site, I’m thankful for the opportunity to write it. I’m glad that I have happened upon something that I find so interesting and at times all-consuming. I’m also thankful that there are people out there who read it – thanks.

From a big picture perspective, I’m also thankful for some of the many unique features of our country that enable this conversation. Because of the foresight of our founding fathers we have the ability to own land privately. Average people can own property that can create great wealth. In another country, this site might only marvel at how some rich land owner whose family received a land grand from a king 400 years ago is getting richer. That’s not the case here. Our free enterprise system has enabled the entrepreneurial spirit that brought little guys with big ambitions to the energy field. The drive and spirit of the folks who own independent gas companies created the opportunities that we see in the Haynesville Shale. I am thankful to them. These are just a few, but list is long.

I try to keep my personal life and opinions out of this site as much as possible, but it’s been a tough week for my immediate family. My wife’s father passed away earlier this week. It has been hard on everyone, especially given the timing of the holiday. But it is in the spirit of Thanksgiving that we are able to share in the strength of family and friends. As her family gathers from far and near, the unity helps soften the blow to the individuals. The experience of this week makes me realize how thankful I am for the little things that I don’t always appreciate, especially about people who are no longer here.

In sum, I am thankful for the love of friends and family, including those who are no longer with us and those who have yet to arrive. Happy Thanksgiving to all!

Wednesday, November 25, 2009

For the past year, I've noted the uncertainty that increased natural gas supply from shale has created for the development of a new natural gas pipeline from Alaska to the Lower 48. Building a pipeline to supply gas to an amply supplied region just doesn't make much sense on the surface. The project, called AGIA, or Alaska Gasline Inducement Act, became a featured project of the former Palin administration and was touted on the McCain-Palin campaign trail, shedding lots of light on the project. Since then, the landscape has changed.

I happened upon a very interesting article that gives some more history and context regarding the proposed pipeline. Perhaps most interesting is the position in which Alaska now finds itself. The state is highly dependent on oil and gas revenues, which flow royalties into the Alaska Permanent Fund that funds infrastructure improvements and provides some income directly to state residents. But because of its remote location, pipelines are the lifeblood of the state's energy industry and control of these pipelines is becoming a bigger issue. With the declining oil fields of the North Slope, some estimate that in the next decade the Trans-Alaska pipeline will not have strong enough flows for operations to remain economically feasible. Gas is abundant but without a means to sell it to the world, it will remain an untapped resource. But with the control issues between the state and the producers along with the supply/demand/pricing issues of the Lower 48, the project remains in limbo.

It's a complicated situation, and the article helps make some sense of it. Or it might just complicate matters.

Chesapeake Energy has been hinting about its aspirations to develop shale fields internationally since last year when it signed a joint venture agreements with Norway's StatoilHydro to develop the Marcellus Shale. News came out today that Chesapeake, Statoil and Sasol Ltd. of South Africa have submitted a bid to explore for shale gas in the Karoo Basin of South Africa. This would be Chesapeake's first international venture, although we understand that Statoil has set up a learning center overseas to facilitate a "brain drain" of Chesapeake's shale knowledge. This likely will not be the last announcement of its kind.

This announcement makes me recall a time not that long ago (last year, in fact) when Chesapeake billed itself as the safe natural gas exploration company because it limited its exploration activities to land east of the Rockies, with nothing offshore and nothing international. I'm sure Statoil and Sasol will bear the economic burden of the partnership, but I am amazed at how far we have come in such a short time.

The Baker Hughes rig count was released a few days early in anticipation of the Thanksgiving holiday. It showed a 24 rig increase in the U.S. Interestingly, it was mostly in vertical gas rigs. The week showed that 22 of the net 24 rig increase was in gas rigs, and 17 of the net 24 increase was in vertical wells. This is different from the recent pattern that has been favoring horizontal oil rigs. I know the Baker Hughes information is oversensitive to short term changes, but this struck me as strange.

In the Haynesville region of north Louisiana and east Texas, inclusive of other formations, the count was up three to 168. There was a one rig decrease in N. LA and a four rig increase in E. TX.

We just can't stop adding gas to storage. Last week, natural gas in storage increased by 2 Bcf to 3.835 Tcf. While it's considerably lower than injections of the past months, 'tis the season for withdrawals, not more injections. Last year this week, there was a 55 Bcf withdrawal and the five year average indicates a 21 Bcf withdrawal for this week.

Hopefully gas traders will have visions of tryptophan dancing in their heads and disregard the still high storage numbers. Just another wrinkle in a long strange ride for natural gas this year.

Verhalen "B" 1H, GMX Resources: 8.19 MMcf/day IP on 23/64" choke; Harrison Co. (Bossier Shale). Interestingly, GMX self-reported this well at the end of September but only with a 5.7 MMcf/day IP rate. Usually the deviation between the press release and the official report goes the other way.

Sunday, November 22, 2009

I read an article in the Shreveport Times this morning about the three fatalities that have occurred at Haynesville Shale well sites this year. I had two thoughts when I read the article: 1) how my cynicism about corporate safety programs has changed over the years and 2) how the boom-bust oil and gas industry has cost it many experienced workers.

First, the article mentions that the experienced workers and the companies themselves make safety a priority. Some people might be skeptical when they see "Safety First" emblazoned on the back of a company truck - I used to be. It took me a long time to realize that in a people-based industry like drilling, safety is money and business is all about money. Accidents and injuries cost the company money in lost production, higher insurance rates, etc.

But more importantly, a dedication to safety is a good way to keep the best people, and in a people-based business that is of paramount importance. The best workers aren't going to work for a company with a culture that fosters a dangerous workplace for long. They are going to try to work at the company where they will be safe. I heard a business owner say the other day that one of the best things his company can boast to new hires is that its workers make it home safely at the end of every day. Clearly not everyone in business values safety the same way. In this world of budget cuts and balance sheets, safety programs do get trimmed, but clearly it's a bad idea.

Second, the article points out through interviews that there are many inexperienced hands working the rigs in the Haynesville Play. The article notes that the "gold rush" mentality has brought many workers new to the gas industry to the market and the sheer number of rigs requires lots of workers. I've heard and read anecdotal evidence that the boom-bust nature of the gas industry over the years has caused many workers to leave the industry for more stable occupations. The last boom-bust wave cost the industry untold number of experienced workers. These are the guys who "set the pace" on the job and mentor the younger guys. Without that wealth of experience, the industry has to depend on fewer experienced workers and lots of inexperienced younger workers. As the industry ramps up to drill the high pressured, and therefore more dangerous, Haynesville Shale, the dearth of experienced workers will be a problem.

Now that the gas industry is drying up in other places, more experienced workers are migrating to the big shale plays. Hopefully that will help improve the culture of safety and properly train younger workers who are the future of the industry. I hate to read about these accidents. Safety first.

Friday, November 20, 2009

The Shreveport Times published an article about the Mid-Bossier Shale (a.k.a. Bossier Shale in Louisiana) that might touch off a frenzy in DeSoto Parish, as Chesapeake Energy's geosciences manager John Sharp gave a speech to a Rotary group and basically called Mansfield the center of the universe, at least in regards to natural gas drilling in the U.S. His point was that DeSoto sits on top of both the Haynesville and Mid-Bossier Shales. Not only did he predict great activity from the drilling industry, he predicted a housing boom in the area.

While it's best to leave the real estate prognostication to others, Mr. Sharp has a point about the stacked Haynesville/Mid-Bossier plays. We've been following this since July when EnCana became the first gas producer to talk about the Mid-Bossier in its investment presentations.

I've always been partial to maps, so the first thing I always want to know is what does it look like/where is it? It seems that just like the early days of the Great Haynesville Shale Rush, the exact boundaries of the Mid-Bossier formation are not entirely settled. What is known is that it was formed by a similar process to the Haynesville Shale, only later and likely in a smaller geographic area towards the southern part of the Haynesville formation. I've published information about the geology and several maps with the Mid-Bossier Shale noted, but below I've collected them, along with a new one from Petrohawk (the first one below - the Mid-Bossier Shale is in purple).

The one below is from Regency Energy Partners, a pipeline company. The Mid-Bossier is in pink.

This one is from Chesapeake. It notes the two Mid-Bossier wells the company has drilled.

The one below is from Exco. I find it to be the least informative. The Mid-Bossier is in peach.

There is no definitive answer here, and one's feelings about the boundaries of the Mid-Bossier might be slanted by the land one has leased, but what seems to be for sure is that it will be a busy decade in DeSoto Parish and the rest of NW Louisiana/E Texas.

Another week of wildly fluctuating natural gas spot prices comes to an end. The Henry Hub natural gas spot price closed down 44 cents, or 12.4%, to close at $3.11/MMBtu.

Since last Friday's close was $2.44, that implies a gain of 27.5%. Sounds good on the surface, but what a wild ride to get there! The average change of the daily closing price this week was 13.3%. Glancing back at the period between June 1 and August 31, the daily change never got into double digits, and the average daily change was 3.3%. Since September 1, the average daily change has been 7.4%. In the last 57 trading days since September 1, there have been 12 days when the closing price change was greater than 10%.

That volatility is astounding, but I guess it's not entirely surprising given the weird world that natural gas finds itself in these days.

The Baker Hughes weekly rig count showed yet another increase in U.S. rigs, rising by 12 to 1,113. It's perhaps not a surprise that 12 rig increase resulted from the addition of 14 oil rigs and the subtraction of two gas rigs. Last year, gas rigs represented 78% of all active rigs, but that figure is only 65% this year.

Nor is it much of a surprise that the net 12 rig increase resulted from the addition of 19 horizontal rigs and the subtraction of five directional rigs and two vertical rigs. Horizontal rigs now represent 48% of all rigs currently deployed, compared to 33% this week last year.

In the Haynesville area of east Texas and north Louisiana (which includes other formations), the rig count increased by eight to 165. All of the new rigs were in Louisiana.

Thursday, November 19, 2009

There was a well blowout near Mansfield in DeSoto Parish yesterday morning that killed a man and left another critically injured. The well, the Sumner 25H-1, is operated by Chesapeake Energy and located in the North Grand Cane Field (serial #239860). SONRIS last reports it as fracked with flowback on September 25, and the paper reported it as producing. The men were doing "routine maintenance" when the blowout occurred.

Lest we all forget while we think of all the good things that come from the Haynesville Shale that the extraction of gas from these highly pressurized wells is a very dangerous job. Our thoughts and prayers go out to the families and friends of these men.

I’ve gotten several questions about how production companies calculate royalties. I have been reluctant to answer this question before because I hate to encourage chicken counting when the eggs are new. I am not an expert, but I can tell you what I’ve figured out from my own experience.

I have seen statements from six or seven different producers over the years, and each one is different in terms of layout and the level of detail of information disclosed. I have to say that for the average person these statements are poorly organized and hard to decipher. Keep in mind that royalty payments depend on whether or not the owner has a lease and if the section (in Louisiana) has been unitized. I’ll explain what I know using a unitized Louisiana gas example, but remember each situation might be different.

First, you don’t see any royalties from production for two to three months, usually three. The statement usually shows a gross calculation (the whole well) and the net calculation (you as royalty owner). Each monthly statement will cover all of the wells for that operator. Looking at an individual well, you will see the total gross volume of gas produced in the month. Then you will see a commodity price. This price is a weighted average price based on how much gas was produced each day and the wellhead price for that day. The producers usually use a wellhead price to calculate royalties. (I follow the Henry Hub spot price as a proxy for wellhead price, but they are not exactly the same. Wellhead prices depend on well location and a host of other factors, so they are hard to generalize. You can also look at the NYMEX near month contract, which is the most commonly used natgas price. Most importantly, don't fall in love with the prices you've seen over the month. My experience is that wellhead prices are a little lower than what you are used to seeing.) What is for sure is that the producer’s hedged prices that they trumpet for investors are what THEY sell the gas for, not the price on which they base royalties. Multiplying gross production by price, you get gross revenue for that well.

From that amount is deducted state severance tax, which is not a whole lot in LA, and some operating expenses. Usually the operating expenses column is a black box, but sometimes operators break out the expenses. They can include the costs of gathering, processing, treating and transporting the gas. There is no hard and fast rule, but these costs usually amount to 8-15% of gross value. It's a big variable that applies differently to different wells and leases, as some leases do not allow for transportation costs. Even if you don't pay costs, you still pay severance taxes. Those costs are subtracted from the gross revenue to get the net revenue.

Multiply that net revenue amount by the owner interest – the percentage you own – and you get the net royalty payable. Before you get too excited about your 20-25% royalty rate, remember that in Louisiana wells are paid out by 640 acre sections. If you have a 25% royalty rate and own 160 acres of the section in question (25%), your applicable interest is 25% of 25%, or 6.25%. If you own that interest 50/50 with your sibling, your net interest is 3.125%, or 0.03125.

Here is a sample calculation using dummy numbers:
250,000 Mcf produced in a month multiplied by an average price of $3.15/Mcf = $787,500 gross revenue. Subtract from that severance taxes and delivery expenses of $78,750, 10% in this example, to get a net revenue amount of $708,750. If your ownership percentage is 3.125%, you are looking at a net royalty amount of $22,148 from that well for the month.

Another thing to keep in mind is that operators often go back and make adjustments on the statements for past months to correct volumes, commodity prices, expenses, etc. using more accurate figures. As a result, after a few months your statement will have lots of strange line items with big positive and negative numbers flying around that might yield an adjustment of $0.43 or something like that. Or it could be a substantial adjustment. It gets very confusing. Usually I find that the adjustments from previous months tend to cut against me, but not always.

Don’t forget taxes. First, let me say, I DO NOT GIVE TAX ADVICE, so please, please, please consult a tax advisor. In January of the following year you will get a 1099 form from the production company stating your net revenue. It might not match your checks because of the timing of the revenue, but it should be close. The IRS gets a copy of this too. Keep two things in mind:

You are entitled to deduct a portion of that revenue as “depletion” expense from your taxes, often 15% is used. That reduces the taxable revenue on which you pay income taxes. It’s like depreciation expenses for businesses.

If you don’t do quarterly estimated tax payments you might want to start. If your taxable income spikes and you haven’t been paying quarterly estimates, you might be penalized (with interest) come April 15.

The only tax advice I will offer other than seek professional advice is this, don’t spend it all in one place. Remember that you will have to pay taxes on it, either quarterly or on April 15. Don’t let it surprise you and bite you in the rear.

I was a bit disappointed to see that natural gas in storage is still going up. Last week it was up 20 Bcf to 3.833 Tcf. Of course this is another new record. Last year this week, storage increased 23 Bcf, while the five year average for this week is a 10 Bcf increase. The storage graph below shows the red line (this year's storage figure) still peaking over the five year average.

The new storage was fairly equally distributed across the three regions, +8 Bcf in the East, +3 Bcf in the West and +9 Bcf in the Producing Region. Interestingly, the Producing Region storage stands at 1.208 Tcf, which is higher than the estimated peak capacity of 1.202 Tcf. I guess they're really squeezing it in. Total storage stands at 99% of the demonstrated peak capacity of 3,889. I can't help but think of the Monty Python sketch about Mr. Creosote and the wafer-thin mint.

Looking at the warm temperatures for the past week, it is no surprise that gas usage didn't surge.

As I was reading through Devon Energy’s third quarter results, I saw splashed across the news that the company planned to “strategically reposition” itself as a “high-growth, onshore North American exploration and production company.” Zoikes. To achieve this goal, Devon plans to sell its Gulf of Mexico and foreign properties, most of which are offshore.

The rationale is fairly simple. Offshore exploration is a high risk-high reward proposition that requires loads of capital committed years in advance. Building production platforms, leasing drilling equipment, building pipelines, supporting a mini offshore village takes serious cash. But there are no guarantees of hitting a monster well to reward this risk. Now that onshore shale drilling has become economically viable (largely thanks to Devon/Mitchell Energy’s work in the Barnett Shale), gas production companies can build their reserves onshore in a lower relative risk environment. The downside is that it also dooms the company to having to sell gas into an oversupplied, price-depressed domestic market. At least with foreign projects, the company would not be limited to the North American price environment. Perhaps Devon is making a big visible wager on a brighter future for gas consumption in North America.

Management stated in interviews that they didn’t feel the market appropriately valued the offshore and international assets. Will Devon be the last company to recalibrate its business plan and slide down the risk-reward continuum to concentrate on shale gas? I don’t know. Not too many big shale independent producers have international interests. Anadarko comes to mind, but they hardly dabble internationally.

Devon also made news earlier this month with the announcement of its Kardell GU #1 well in San Augustine Co. Texas, which had a sporty 24 hour initial production rate of 30.7 MMcf/day. The well was running at a 37/64” choke (to get out the remaining frac fluid, the company said) and had a flowing casing pressure of 6,800 psi. The company noted in its conference call that the well is about 2,000 feet deeper than Carthage area wells and is more highly pressurized. The well is operated by Devon, which has a 48% working interest. The big well is stirring lots of interest in San Augustine Co., as one might expect.

The Kardell well is in the southern part of Devon’s 570,000 net acres. Much of this land is held by production, but looking at the map below, a lot of the Louisiana property is north of the Shreveport-Bossier area, so the 570K acreage number might not be that impressive. The company has been testing land in its acreage around Carthage over the past year, drilling eight wells. The company noted the Jernigan A 4H well in Panola Co. that had an 8.0 MMcf/day IP rate. Devon is shifting its attention to the south where it has approximately 47,000 acres not HBP in San Augustine and Sabine Counties, TX and Sabine Parish, LA. The company estimates that it will have to drill 105 wells over the next two years to hold these leases. The Kardell well was drilled as part of this effort, so I’d imagine that Devon will follow through with these 105 wells.

The company plans to operate five Haynesville rigs in 2010 and participate in other non-operated wells on its acreage. In terms of estimated ultimate recoveries, Devon thinks the Carthage area is good for 5-6 Bcfe EUR. It doesn’t have enough information about the southern part of the play to make a good estimate, although it thinks the Kardell well will be a 6 Bcfe well.

I certainly don't hold myself out as an international economist, but it seems as though the supply part of the supply/demand pricing equation is undergoing fundamental change worldwide, not just in the U.S. Russia uses its gas pipelines for political gain in Europe, but this position seems to be weakening as Europeans have access to more sources of gas.

I'm certain that gas demand will pick up over the next couple of years as the worldwide economy improves, but I think the Russians are selectively ignoring a fundamental shift on the supply side. Does Gazprom know something or are they engaging in political posturing? Or worse, wishful thinking?

The Houston Chronicle had a good article on George Mitchell, co-founder of Mitchell Energy, who pushed for the development of shale gas in the Barnett Shale. Mitchell later sold the company to Devon Energy, which added the concept of horizontal drilling to fracturing shale rock to create the shale gas industry we know today.

The article gives a little more information than an interview published by Forbes earlier this summer. Both pieces shed light on the man who stubbornly pushed for his company to look more closely at developing shale gas.

Monday, November 16, 2009

I haven’t spent much time in this forum discussing the national energy policy/climate change conundrum in Washington, but it’s not because I don’t think it’s important. I want to be careful about wading into such emotionally and politically charged waters without a clear heading. It doesn’t quite pack the politically divisive punch of free-health-care-for-gay-illegal-immigrants-seeking-to-get-married, but the proposed legislation may drive many important business and political decisions for decades to come. Also, concepts like cap and trade are so doggone complicated that I’m having trouble getting my mind around it.

The Financial Times’ Sheila McNulty published a post last week that hits on some of the important points that are being overlooked in the debate and offers some different perspectives. One of the things she hits spot-on is that we can significantly lower our carbon output overnight with very little expense by better utilizing the existing capacity of natural gas-fired power plants in this country. These plants are terribly underutilized, as utilities opt to burn coal because it is economically cheaper than gas. Natural gas, however, emits about half the carbon of coal and significantly fewer noxious pollutants, so shifting a large portion of power generation from coal to existing natural gas would lead to a significant immediate decrease in carbon emissions. Obviously, the process to get to that end might be complicated, but it doesn’t have to be expensive.

This is not a long-term solution toward creating a zero-carbon regime, but it is an easy and meaningful near-term change to stop the bleeding. Another relatively inexpensive way to lower power consumption and thus carbon emissions is a greater emphasis on efficiency. The “low hanging fruit” abounds, but the concept has been lost in the fighting. Neither of these ideas is sexy, but they will work. Unfortunately with the various constituencies battling it out from the extremes, the energy/climate fight becomes a noisy, static-filled mess.

Most baffling to me is the position of many renewable power advocates. Intellectually, I understand their position that the U.S. should focus entirely on renewable energy sources and that embracing natural gas would be giving in to fossil fuels. I get it, but I think it’s wrong. Renewable energy needs all the friends it can get, especially now that it’s not commercially scalable. I worry that those in the green movement are blinded by their long-term vision that that they are willing to give up tangible progress to further their long-term goals. To me that makes them worse than the polluters. It looks like some renewable power advocates depend on the continued use of coal to make the climate situation worse so they can better advocate for renewables. Environmentalists and coal: what strange bedfellows politics make.

Unfortunately I was not able to go to the second annual Haynesville Shale Expo, held in Shreveport last week. I did note an article in the Shreveport Times about one of the presentations, where the speaker, Gary Hanson, Director of the LSU-Shreveport Red River Watershed Management Institute, declared that there's been "a paradigm shift in the past few months in how the industry looks at water and it started here." Hanson noted that most of the big Haynesville producers, at least in Louisiana, have been using surface water or other alternatives to underground aquifers, including pond water, water piped from the Red River or various forms of recycled water, in the hydraulic fracturing process.

The recent commotion over water in the Marcellus Shale over water is wider-reaching. Residents of the Appalachian region are concerned about the sources for the millions of gallons of water required for fracking, but they are also worried about the chemicals that are part of the drilling fluids and the management of the waste water from the gas wells. Those are not issues that will be quickly or easily resolved. They are, however, not entirely new for the region. Coal mining has polluted waterways and groundwater for the past century. Perhaps the recent uprising has as much to do with Appalachian residents' inability to go back in time and better regulate the environmental impact of the coal industry as it does with the current situation.

Saturday, November 14, 2009

I’ve been in a contemplative mood this week. I’m thinking about the future of natural gas and it doesn’t seem as rosy as it once did without new sources of demand. Two things got me thinking: third quarter earnings reports from Haynesville gas producers and the realization that many new coal powered electricity plants will come online next year.

Reading through the third quarter earnings reports from Haynesville gas producers, I saw that most companies saw increased production or slightly lower production with a decrease in new wells. The bottom line is that shale wells are out-producing conventional wells exponentially. The production companies cut back rigs and the gas keeps coming. Good news in a way, I suppose, but not so much in this stagnant demand environment.

In deference to T. Boone Pickens, I think that gaining market share in the utility industry is the best opportunity for natural gas demand to increase. The infrastructure of functioning gas-fired power plants is already there. All utilities need to do is make the decision to burn more gas than coal. But the realization that approximately 4,300 Mw of new coal-fired electrical power production will come online in 2010 really bums me out. Power producers didn’t build these plants to mothball; they built them to burn some dirty coal. Mountains of coal have been piling up at electricity plants for the past year while many power producers chose to run on gas while the commodity price was extremely low. Now all of a sudden you’ve got a bunch of shiny new coal plants and mountains of stockpiled, already paid-for coal. What are you going to do? Burn some coal!

These are near-term concerns, but they point to the elephant in the room, which is a permanent state of natural gas over-supply in the U.S. No matter what people like Arthur Berman and Matt Simmons say, increased natural gas production is the new reality. No matter how fast the new shale wells decline, as long as they produce large quantities of gas quickly, the E&P companies are going to drill shale wells as fast as they possibly can. I’m not saying that Messrs. Berman and Simmons are wrong – I’ve got neither the technical knowledge nor the access to the data to make an educated analysis – but if shale wells produce big numbers out of the gate and pay for themselves in a short period of time, E&P companies will continue to drill them.

Internal rate of return (IRR) is an important metric that is used in analyzing the economic returns on gas wells. Because IRR is a time weighted return, the sooner you get back your investment, the higher your IRR. Even if you don’t make 4x your investment, if you get your money back in the first six months, you are looking at a juicy IRR that you can flaunt to your shareholders. That creates an incentive for the E&P companies to drill, baby, drill. The truth is that the terrestrial gas industry has always grown by drilling. It’s never hit the big one and sat back on its laurels. It’s always out there drilling the next well. But what about the rest of us? As long as E&P companies drill until there are forced to curtail production because of storage constraints, we will see depressed natural gas commodity prices.

Ultimately, the new supply paradigm puts the gas industry in a hole. Without new sources of demand, the gas industry is the guy who is getting fatter and fatter but is stuck with a pair of size 32 jeans. You’re getting more uncomfortable every day and there’s nowhere to go. If you don’t get higher penetration in the utility sector or see a bunch of new natural gas vehicles on the road, we are going to be stuck with $2 to $4 gas prices as far as the eye can see.

Producers have been able to successfully drill expensive shale wells because they can hedge gas prices out to the future. If the market participants believe that gas prices are going to be low for the next decade, the futures prices will drop and the hedging opportunities will evaporate. Most new shale gas wells are not economically feasible based on current wellhead prices. Of course then shale drilling drops. But what about the rest of us?

Increased demand is not an area where I believe the gas industry is asleep at the wheel. If there is meaningful climate change/energy policy that favors natural gas enacted or if strong incentives to switch vehicles to natural gas are created, I think natural gas demand will increase significantly. But if neither happens, we are looking at a future of artificially low gas prices and an industry with few winners. That’s what keeps me up at night.

Friday, November 13, 2009

The Henry Hub spot price for gas dropped 79 cents, or 24.5%, to $2.44 today. That's a 46% drop since last Wednesday November 4! I assume it is related to the storage figures released earlier today, but I've given up on trying to figure anything out these days. The purple/blue/periwinkle line on the chart below shows the extreme price volatility for the past few months. I need a drink.

The Baker Hughes rig count showed another week of increased rigs in the U.S., rising by 23 to 1,101. Of those rigs, 728, or 66%, are gas rigs.

In the Haynesville region of east Texas and north Louisiana, which includes some other formations, the count increased by six to 157. There were three fewer rigs in north LA this week and nine more in east TX.

EnCana led its quarterly earnings call by noting that it had shut in or curtailed approximately 500 MMcf/day of gas production companywide in the third quarter because of low commodity prices. EnCana expects to bring these streams back online this winter.

Unfortunately, EnCana didn't spend a lot of time addressing the Haynesville Shale in its third quarter announcement or conference call. It noted that the company drilled 12 net wells (I assume that means about 24 gross wells since most of the company's land is under a 50/50 deal with Shell) at an approximate cost of $8 million. The company is seeing daily net production of about 130 MMcf (260 MMcf gross I assume), although presumably part of that has been curtailed because of low gas prices.

In terms of 2010 capital budget, EnCana will allocated $750 million to the Haynesville Shale, a figure that represents 40% of the company's U.S. budget and around 19% to 21% of the total capex budget of $3.6 to $3.9 million (all figures $US).

I was a little disappointed, but not surprised given the relatively warm weather last week, to see a 25 Bcf increase in natural gas storage this week. The 0.7% increase in working gas in storage brought the figure to 3.813 Tcf. Since storage levels eclipsed their previous record high levels in September, this is obviously yet another new high. The map below shows that temperatures across the country were pretty mild last week and generally above normal for this time of year.

While I was disappointed to see growth in storage, I note that the 25 Bcf is lower than both last year's injection (54 Bcf) and the five year average (30 Bcf). The differential over last year shrunk from 11.1% to 10.1%, and the differential over the five year average shrunk from 12.3% to 12.0%. While it is slight progress in the right direction, the graph of the current year versus the five year average is still ugly.

I've got a problem with that. First, the natural gas industry contends that the chemicals in question are a very small component of the overall contents of the frac fluid, approximately 0.6% or less. If you inject, for example, three million gallons of fluid into the well, you’re talking about 18,000 gallons of chemicals. The industry contends that the chemicals are for things like lubrication and corrosion prevention and are as safe as the chemicals you might find below your kitchen sink. I moved the chemicals below my sink to a shelf high in the pantry when I had kids, so that’s not helpful guidance.

Second, if you refuse to disclose the contents of what you describe as a miniscule component of your secret sauce, it makes it look like you're hiding something. The more recalcitrant you are, the guiltier you look. Playing the tough guy doesn't work in this new information society. This is not a court of law. In the court of public opinion, you are guilty until you prove yourself innocent.

Just look how resistance to drilling in the Marcellus Shale has grown exponentially over the past couple of months since a fish kill in Dunkard Creek was erroneously attributed to gas drilling (I say "erroneously" because it is not fully understood what caused the kill, but it doesn’t look like the gas producer). These days, withholding information is considered the same as lying. You are guilty before being tried. Opposition grows overnight like Jack’s beanstalk and it is fed by misinformation from your opponents, over which you have no control. The Dunkard Creek incident is a cautionary tale of how fast resistance grows in the 21st century.

I fully support the use of fracking. As I've stated in the past, I think the issue is not what happens underground but rather what happens at the surface. How the fluids are handled before they are injected and after they come back up is of paramount importance. At the same time, however, I believe the surface environment must be protected at all costs. I hate to say it, but IT IS the government's job to protect all the people's rights, and that doesn’t start with turning a blind eye towards the environment to benefit business interests. E&P companies are businesses and as such have a responsibility to their owners (me, among them) to produce hydrocarbons from below the earth and make a good profit. It's not their jobs to protect the surface. It is in their best interests to protect surface uses, but it is up to the government to enforce the rights of those who are not their shareholders.

Believe me, I don't want to see the Frac Act or any other regulation of hydraulic fracturing. I own a piece of the golden goose, but I want her to keep producing eggs for the rest of my lifetime and for generations to come. Having the IPPA play the bad cop is not in my best interest because I want to balance what happens at the surface with what is produced from underground. Honesty is the first step to a better future for all of us. Digging your head deeper in the sand is a recipe for disaster.

Since last Wednesday, when the Henry Hub spot price of natural gas closed at $4.49, the spot price has been on an ugly losing streak, dropping 28% in that short time. Today, the Henry Hub price dropped 10% to close at $3.23.

Normally natural gas storage numbers come out on Thursday, but the release was delayed until tomorrow because of the Veterans Day holiday.

With my travel and day job schedule I’ve been delinquent in reporting/reflecting on Haynesville producers’ third quarter results. There is lots of good stuff that likely will take me a couple of weeks to process. First up, Petrohawk (HK). I’ve always found HK to be a good barometer of the Haynesville Shale because of its level of commitment to the play relative to the size of the company’s total operations. A long time ago, someone explained to me the difference between being involved in something and committed to it using the example of a ham and egg breakfast. The chicken is involved, but the pig is committed. Using this example, the ‘Hawk is committed to the Haynesville Shale, but not necessarily in a bad way.

Things are going swimmingly for HK, given the difficult environment. Overall production exceeded expectations, as might be expected with some of the strong wells HK has drilled in the Haynesville Play. The company cut its capital budget somewhat in 2009 but is still on track to drill and produce enough to hold its Haynesville leases.

In the third quarter, HK became more committed to the play by spending another $190 million to acquire an additional 53,000 net acres of leasehold, bringing the company’s total to 343 ,000 net acres. The new acreage is in the core area and the southern part of the play. Of the total, 36K acres were in north Louisiana and 17K acres were in Texas. HK announced its 2010 capital budget of $1.45 million, of which 62%, or $900 million, will be allocated to Haynesville drilling.

To date, HK has drilled or participated in 116 wells in the play. In the third quarter, the company drilled 24 wells (23 in LA, 1 in Shelby Co. TX), completed 18 and brought 14 to production. The average IP rate (presumably peak 24 hr rate) was 18.6 MMcf/day, ranging between 12.6 and 25.5 MMcf/day. In total, HK has 62 producing Haynesville wells generating 450 MMcf/day, and of those, 53 have been producing longer than 30 days. The average first 30 day production rate for those 53 wells was 14 MMcf/day.

HK is experimenting on some of its wells to choke back production to 14/64” and below to see if slower extraction will lead to shallower decline rates and presumably higher ultimate recoveries. So far, HK is testing four wells, and they are producing 8-9 MMcf/day at flowing casing pressures of 8,500 psi and above. I’ve noted that some other producers are trying similar experiments. While the company is a long way from drawing definitive (or at least educated) conclusions from these tests, I can’t help but wonder if the days of macho high IP rates might be coming to an end.

The press release had lots more information on improvements in drilling and completion techniques, including the development and implementation of a new “game changing” polycrystalline diamond compact drill bit. The release also noted that average well costs are around $8-$9 million, versus an average of $9.5 million YTD, and drilling times are shorter.

HK also mentioned that it has been looking hard at the Mid-Bossier Shale (they call it the Lower Bossier, but I find that confusing with the nomenclature in Texas, so I call it the Mid-Bossier to reinforce that it is above the Haynesville Shale). While the company hasn’t completed any Mid-Bossier wells – their first will be in Q1 2010 – it has accumulated technical data and drawn several conclusions. First, approximately 122,000 net acres of HK’s leasehold is prospective for Mid-Bossier Shale. Second, the rock quality is as good as the Haynesville formation only in places, not throughout (but it is still quite good). Third, the company expects recoverable gas to be about 75% of what it expects in the Haynesville, in the range of 5-6 Bcfe from Mid-Bossier wells. Right now the technology doesn’t exist to drill a Mid-Bossier well from a Haynesville well, so MB wells will be free standing for now.

I have to chuckle at how far we’ve come in the past couple of years. In 2007, producers would strip naked and do cartwheels in the streets of downtown Houston at rush hour for 122,000 acres of 5-6 Bcfe potential wells that are held by production. Petrohawk is excited about the Mid-Bossier, but there were no cartwheels.

"The Haynesville Shale doesn't have to be a win-lose proposition. There is an appropriate balance between helping develop this industry and the reasonable cost of doing business. Pulling natural gas from the ground will enrich many people, but it shouldn't come at the expense of the land and people by sacrificing the region's environment."

Gas and oil has been produced from north Louisiana and east Texas for the past century and production likely will continue for generations to come. It is paramount that we do not squander this opportunity by short-sighted thinking on all sides. Louisiana has a long and inglorious history of failures where it comes to our energy resources. Outside of the state's excellent conservation laws, there is not much positive to point to with bad royalty deals, cronyism, sliced and diced wetlands and lax environmental oversight.

Let's balance our current needs and (justifiable) lust for immediate dollars with the necessary protections to our infrastructure, natural environment and future earning potential. Decisions made today will impact our lives for generations to come. Visionary long-term thinking is required to chart a new course for the future.

Wednesday, November 11, 2009

I've been critical of the natural gas industry's weak effort in gaining a seat at the table (rather than being on the menu) for the negotiations over energy and climate change legislation. Over the past six months, the industry has been making up for its past failures in a big way with a lobbying push and very active public relations and marketing campaigns. I noted a good article from Reuters last week on the progress that the natgas industry has made in the Senate's version of the legislation. It's a long way from being done, but it's great to see progress.

In September, a large fish kill in Dunkard Creek, along the Pennsylvania/West Virginia border, set off alarm bells across the Appalachian region when it was originally reported that the fish kill was the result of a spill of drilling fluids at a natural gas well. The reporting of the spill and kill created a uproar among environmentalists, land owners and many others about the safety of gas drilling and especially hydraulic fracturing. Because the event occurred in the highly populated Northeast, it was widely reported, which led to a huge uproar that the natural gas industry has been fighting for the past two months.

Now I read a Pittsburgh Post Gazette article from last month that the cause of the fish kill is more complex than originally reported and likely not the result of a spill at a gas well. While officials might never know the cause of the kill, many believe that golden algae, a warm water algae that is not native to the area, is to blame. If this is the case, the culprit may indeed be the natural gas industry, as the algae may have been attached to drilling equipment from Texas, where the algae is known to occur. This, however, is just one theory being considered. There is also evidence that local coal producer Consol Energy has been discharging treated mine water with extremely high levels of dissolved solids and chloride into the creek.

Whatever the case, water in the Dunkard Creek has been deteriorating since 2002, partially caused by coal mine water treatment facility discharges from two Consol mines in the area. I hate to be paranoid, but I'm sure the coal industry is happy to help point the finger at natural gas when the coal industry has not been the best steward of the land. It doesn't help that state environmental enforcement agencies, especially in West Virginia, has been lenient with the coal industry.

The truth of the Dunkard Creek fish kill may never be known, but the damage is done. Natural gas has been branded the culprit and has been fighting an unending battle against people who are genuinely scared for the health of the environment.

Tuesday, November 10, 2009

The impact of shale gas on the supply of natural gas is starting to show beyond the shores of North America. The Wall Street Journal reports that the International Energy Agency has released a report that a natural gas glut is looming. The IEA says the oversupply could have “far-reaching consequences for the structure of gas markets and for the way gas is priced in Europe and Asia-Pacific.” The Financial Times has another good article on the report and its implications.

We've already seen this materialize to a certain extent in the U.S. The combination of lower demand from the recession and increased supply from shale have altered the supply and demand mechanics and thus the pricing of gas in North America. In the U.S., gas is priced as a free standing commodity. In Europe, 70% of gas is sold at a price indexed to oil's price, most of this under long-term contracts. (In the Asia-Pacific region 52% of gas is oil-indexed.) This works great for gas suppliers, especially Russian companies like Gazprom, that provide about a quarter of Europe's gas via pipeline at prices that are rising based on oil's pricing properties.

But on the supply side, there has been a huge increase in natural gas. In the U.S., shale gas has flooded the market, driving down spot prices. While the U.S. doesn't export much gas (yet), it quickly has become a less attractive place to sell LNG. The other supply change is the huge amounts of gas liquefaction capacity coming online in Qatar and Yemen that will create prodigious amounts of LNG. As the U.S. becomes a less attractive place to sell gas, uncontracted LNG goes to Europe and Asia, driving down prices on their spot markets. The differential between the declining spot and the oil-indexed contracted prices is causing great agita among gas consumers, especially in Europe.

This seems like a natural occurrence with the increase in LNG capacity. As natural gas becomes more of a worldwide commodity, it should be priced independently of oil. Companies like Gazprom want to hold onto the old system, and why not? They have grown fat selling high priced gas to Europe and Asia. If the fundamental pricing mechanism changes, these companies will be stung. Gazprom in particular will be in a tough spot, as it needs huge amounts of capital (and foreign expertise) to develop new gas resources in difficult to reach areas. Just yesterday, Gazprom announced its quarterly earnings. Revenues dropped - as expected with lower commodity prices - but costs remained high, much to the consternation of analysts. Here is another article from Bloomberg about this situation (especially the second half) and an interesting suggestion from Gazprom that the company might buy a U.S. shale producer to gain access to shale expertise. Now that would be interesting.

Ultimately, this will be a market-driven situation. If European gas users have a cheaper viable alternative to Gazprom gas, they will move their purchases away from companies like Gazprom and the link between oil and gas pricing will break.
While it's not Haynesville Shale gas that is directly causing this global market shift, it is playing a part by taking the U.S. out of its role as a gas importer, thus increasing pressure on the existing worldwide pricing mechanisms. Not quite a butterfly flapping its wings in the Amazon and causing a typhoon in Asia, but it's still quite interesting to be impacting the worldwide energy market from our little corner of the world.

The Shreveport Times reported that Louisiana Oil and Gas Association president Don Briggs took a ride on DeSoto Parish's increasingly damaged roads yesterday. The parish police jury was about to enact stricter road regulations before Mr. Briggs promised some action on behalf of his members (at least he promised some meetings...which might lead to action).

DeSoto has become the epicenter of the Haynesville drilling boom, but the largely rural parish of about 26,000 people does not have the physical infrastructure to support drilling operations spread all over the parish. Over the past two years, truck traffic has increased exponentially, causing roadway damage and some unsafe driving conditions. Road safety rightly has become a big issue in DeSoto.

The parish gets a small percentage of state severance taxes and has seen an increase in sales taxes as a result of the Haynesville development. It has also auctioned mineral lease rights for some parish owned property. But these funds are not enough to compensate the local government for the negative impacts of drilling and the changes caused by the increase in activity.

The DeSoto infrastructure situation is a good example of the strains from the impact of drilling. Theoretically, increased tax collections should fund infrastructure improvements, but it should do more than just serve the needs of the drilling and production companies. It should help fund schools and parish services and make the parish a better place to live. If all tax money goes back into serving the industry, is the parish better off with the Haynesville Shale?

It is important to strike a balance between growing the energy industry in north Louisiana and maintaining, nay improving the quality of life. What's the first rule about the golden goose? Don't kill it.

The Energy Information Administration released its Short Term Energy Outlook today. The report forecasts that the average Henry Hub spot price for natural gas in the month of November will be $4.22/Mcf (about $4.10/MMBtu) and $5.01/Mcf ($4.87/MMBtu) in 2010. The EIA suggests the spot price run-up in October was due to cooler than usual weather in the Midwest causing lower than normal storage injections last month. But the EIA doesn't see much opportunity for gas spot prices rise much beyond current prices through the end of the year.

The forecast for next year is not very sunny, in contrast to the feelings of major producers like Chesapeake, which see the gas market evening out and prices growing towards the $7/MMBtu range in 2010-11. Given the high level of storage at the end of this injection season, storage levels at the end of winter should be extremely high unless there is an extremely cold winter. A high level of storage should keep a lid on gas prices next year.

Next year, the EIA sees growth for natural gas in the residential, commercial and industrial sectors but a decline in use in the electric power sector as 4,300 MW of new coal-fired power plants come online in 2010. Natural gas gained market share from coal over the summer of 2009 when the natgas price was extremely low, but with the uptick in prices since the end of August, natgas consumption in the electric generation sector has returned to normal levels. The EIA also sees an increase in LNG imports as large liquefaction facilities in Qatar and Yemen come online. EIA expects LNG imports to rise from 350 Bcf in 2008 to 470 Bcf in 2009 and 660 Bcf in 2010, continuing to pressure domestic supply levels.

The EIA doesn't have a crystal ball to predict the future, but it does have a mountain of data from all sectors of the energy market. But, quoting the warning on all financial products, "past performance is not indicative of future results." Who will be right? Are major gas producers engaging in wishful thinking? Is the EIA wearing blinders? We'll see...

Saturday, November 7, 2009

In an odd sounding transaction, at least from my perspective, Southern Star Energy, a small player in the Haynesville Shale, is merging with two other companies, Lion Energy Corp. and Gold Star Resources, to form a single "mid-sized, well capitalized" company. Southern Star holds a 40% interest in 5,000 Haynesville Shale acres. The press release seemed to indicate that Lion will be the surviving entity.

It sounds like a strange deal to me because Southern Star is merging with two Canadian companies that have what sounds to be unproven oil and gas interests in Africa. Not to sound disparaging, but seeing as the combined price of a share of stock from all three companies is less than the "meter money" in my car's coin tray, the transaction seems to be one of those speculative penny stock deals.

Southern Star was one of the first companies to make noise about the Haynesville Shale in 2008, but big players quickly overshadowed it. I don't know the behind the scenes story here, but it seems to point to the need for gas producers in the shale extraction business to be large scale companies. I keep wondering if the smaller independents will be able to play in the "big leagues."

Friday, November 6, 2009

I've been traveling today, so I'll combine posts week-ending posts. First, rig count. The Baker Hughes count for the U.S. was up by nine rigs to 1,078. Of that number, 68% were gas rigs - same as last week - and 47% were vertical - up 0.5 percentage points this week.

In the Haynesville region (including some other formations) the total rig count was down by two to 151. The count decreased by six in east Texas but increased by four in north Louisiana. North Louisiana now represents 15.1% of the gas rigs running in the U.S.

Second, gas prices. The spot price closed down 9% to $3.91/MMBtu. It was a volatile week with the price reaching as high as $4.49 and sinking as low as today's price. The average close for the week was $4.25.

Thursday, November 5, 2009

I was a little disappointed to see that natural gas in storage increased 29 Bcf, or 0.8%, last week to 3.788 Tcf. It is a very average injection - both the differentials over last year and the five year average remained virtually unchanged, so it is in line with previous injections - but I was hoping for a lower number. Nearly all of the new gas in storage, 27 of 29 Bcf, ended up in the eastern consuming region.

Two pertinent observations from EIA:

1. Temperatures last week were 2.9 degrees above the normal temperatures for the week, and judging by the map below they were warmer in the more populated areas, so there was not much gas in demand for heating. Last week's temperatures were also 4.3 degrees warmer than that last year's.

2. The storage of 514 Bcf in the west region has now exceeded its estimated peak working gas capacity of 509 Bcf for the second week in a row. The figure noted above is a theoretical figure and is lower than the actual design capacity, which also theoretical. Here is a link to the 2009 revised EIA gas storage capacity estimate.

Since last week marked the end of the storage season (plus or minus a couple of weeks), I hope to see that storage number drop next week. Of course that is fact-free speculation and given the mild weather forecasts I have seen this week, it is no better than wishful thinking.

No, I'm not talking about the growing water wars or the NIMBYism in the NY/PA region but a new HBO series about the "gas rush" in the Catskill Mountains of New York state. Reuters reported a couple months ago about a new series, as of yet unnamed, written and produced by Pulitzer Prize winning author Richard Russo focusing on the many tensions of the possible gas boom in rural New York. The series is based on an article in New York Magazine by David France, who lives in the area.

The HBO series sounds interesting (the tension between the various landowners, the unknown resource beneath their feet, the environmental concerns, etc.). With the proliferation of shale gas in the U.S. it is becoming a more universal issue.

Wednesday, November 4, 2009

The second Shale Expo will take place next week on November 13 at the Shreveport Convention Center (link to article; link to shaleexpo.com). The event is free and is sponsored by the Regional Chambers of Commerce.

On a completely unrelated matter, I'm getting sick of standard imagery for natural gas, especially a blue flame coming out of a stove. The image pasted to the right is stolen from the Shale Expo site. It is actually one of the better "kitchen images" I've seen. For some reason, most of the blue flame pictures I've seen remind me of the cruddy apartment I lived in after college, which brings back some unsavory memories.

Can't we come up with better imagery for natural gas? I guess it is hard to depict. True, it is invisible and it exists in gas form. Yes, it is only truly tangible to 99% of us when it comes out of the stove, but I'm just so tired of it. Makes me envy oil, with its iconic black droplet. "Black gold, Texas Tea." What's natural gas? If we use the blue flame, let's at least see some interesting flame sources, not just kitchen burners. Something cool and high tech.

Exco Resources released quarterly results yesterday. Exco has been a surprisingly big player in the Haynesville Shale with many of the top performing wells to date, at least in terms of intial production.

Because of this success as well as its recent joint venture agreement with Britain's BG Group, the company announced that it will increase the total number of Haynesville wells spudded in 2009 to 43 (up from 27) and complete 27 of those (up from 20). The 2009 capital budget will come in around $535 million. To date, the company has 17 wells flowing, having completed eight in the third quarter, and as of October 16 is producing 213 MMcf/day from the Haynesville play.

In 2010, Exco plans to run 14 rigs (it currently runs ten, with the recent addition of three) and dill 125 wells (including non-operated). The company expects to complete 24 wells in the first quarter of 2010.

Exco is also looking at the Mid-Bossier Shale. It has some core samples and plans to drill a Mid-Bossier well in the fourth quarter of 2009. In analyzing test results, the company notes that the Mid-Bossier thickness is around 1,500 feet, compared to 300 to 400 feet for the Haynesville. The company did not mention any porosity, permeability or other geologic results in its releases, so thickness is not much to go on. We will look for the results from the Mid-Bossier well in Q1 2010. If I'm reading it correctly, the company's take on the size of the Bossier Shale is considerably different (and bigger) than its competitors'.

Tuesday, November 3, 2009

Southwestern Energy reported earnings this week and discussed its promising Haynesville Shale completions in Texas. SWN is in a 50-50 joint venture with a private company that it declines to name in its company materials, but I believe that it is Common Resources, LLC, which is listed as the operator of several of the completions noted below. SWN has approximately 32,800 net acres in the Haynesville/Bossier Shale, most of which is in northern San Augustine and southern Shelby counties. The company noted the following completions, some of which are not very current:

Three more wells are in process: Burrows Gas Unit #1, undergoing testing; Red River 257 #1, awaiting completion; Red River 257 #2, drilling. The company plans to drill one more well in 2009. The Red River 257 #2 is targeting the Mid-Bossier Shale, which should provide another much needed data point to understand the potential of that formation.

In the company's conference call, management suggested that the higher IP rates it has seen in places might be the result of a higher carbonate ratio in the formation that makes the stone more brittle and prone to fracturing versus other places in Texas.

Southwestern is currently producing 34.7 MMcf/day gross, which equates to 10.2 MMcf/day net. The map below, while somewhat dated, shows the general area of SWN’s activity.

Today's Wall Street Journal op-ed page featured a half page article called, "America's Natural Gas Revolution" by Pulitzer Prize winning author Daniel Yergin (try this link if the first one doesn't work). The article gives a good overview of how the natural gas market has changed over the past few years, placing an emphasis on shale gas. The piece doesn't have lots of new information, but the prominence of the author brings the topic to many new eyes.

I mentioned Dr. Yergin last week in relation to his book The Prize and an article he published in Foreign Policy magazine. Recently, his firm, IHS Cambridge Energy Research Associates published research showing huge potential natural gas reserves worldwide from unconventional sources. I guess he's getting lots of PR this days.

Enter Financial Times columnist John Dizard to the fray. He published a column in FT this weekend suggesting that shale gas might be lots of hype and a potential bubble. He bases some of his column on Mr. Berman's work, but his beef is the thought that shale gas is just another way to separate investors from their money. "Ideas like that are why God mad PowerPoint," quips Mr. Dizard.

It's too early to know who is right, but it sure will be interesting to find out over time.

Devon Energy, which is one of the single largest leaseholders in the Haynesville Shale with 570,000 net acres, announced that its Kardell Gas Unit #1H well in San Augustine Co., TX had a peak 24 hour initial production rate of 30.7 MMcf/day on a 37/64" choke at 6,824 psi.

Devon proclaimed it the highest IP recorded in the play to date. Given the fairly wide choke, other producers might quibble with this claim (which is sort of meaningless), but it is certainly the biggest Haynesville well in Texas. Devon owns a 48% working interest in the well, while Crimson Energy owns 52%.

Devon has a long history in the Carthage area, where it has drilled 1,800 wells, including eight horizontal Haynesville wells. This recent success in San Augustine Co. seems to have lit a fire under Devon, which has leases on 47,000 acres in the southern part of the Haynesville Play in San Augustine and Sabine counties (TX) and Sabine Parish (LA), land which likely is prospective for the Mid-Bossier Shale as well. The company is planning to run five rigs in the Haynesville Shale in 2010.

It's Been a Gas...

As of 12/31/15, I have stopped updating the Haynesville Play site on a regular basis. I will occasionally post items I find interesting, but I will no longer maintain the data or keep the news current. The site will remain up as an historical archive and a home for occasional musings.

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About Me

My goal is to compile a real-time historical record of the development of the Haynesville Shale.
There is so much going on at any one time that impacts the Haynesville Shale. I weed through the information and summarize the important points.
I look at the micro-trends, such as drilling results and drilling rig activities, focusing on the who, what and where. I also concentrate on the macro-trends that will impact the future of the Haynesville Shale, including the supply/demand issues, the market for natural gas and trends that impact the gas industry as a whole.